Subterranean drilling operations are often performed to locate (exploration) or to retrieve (production) subterranean hydrocarbon deposits. Most of these operations include an offshore or land-based drilling rig to drive a plurality of interconnected drill pipes known as a drillstring. Large motors at the surface of the drilling rig apply torque and rotation to the drillstring, and the weight of the drillstring components provides downward axial force. At the distal end of the drillstring, a collection of drilling equipment known to one of ordinary skill in the art as a bottom hole assembly (“BHA”), is mounted. Typically, the BHA may include one or more of a drill bit, a drill collar, a stabilizer, a reamer, a mud motor, a rotary steering tool, measurement-while-drilling sensors, and any other device useful in subterranean drilling.
While most drilling operations begin as vertical drilling operations, often the borehole drilled does not maintain a vertical trajectory along its entire depth. Often, changes in the subterranean formation will dictate changes in trajectory, as the drillstring has natural tendency to follow the path of least resistance. For example, if a pocket of softer, easier to drill, formation is encountered, the BHA and attached drillstring will naturally deflect and proceed into that softer formation rather than a harder formation. While relatively inflexible at short lengths, drillstring and BHA components become somewhat flexible over longer lengths. As borehole trajectory deviation is typically reported as the amount of change in angle (i.e. the “build angle”) over one hundred feet, borehole deviation can be imperceptible to the naked eye. However, over distances of over several thousand feet, borehole deviation can be significant.
Many borehole trajectories today desirably include planned borehole deviations. For example, in formations where the production zone includes a horizontal seam, drilling a single deviated bore horizontally through that seam may offer more effective production than several vertical bores. Furthermore, in some circumstances, it is preferable to drill a single vertical main bore and have several horizontal bores branch off therefrom to fully reach and develop all the hydrocarbon deposits of the formation. Therefore, considerable time and resources have been dedicated to develop and optimize directional drilling capabilities.
Typical directional drilling schemes include various mechanisms and apparatuses in the BHA to selectively divert the drillstring from its original trajectory. An early development in the field of directional drilling included the addition of a positive displacement mud motor in combination with a bent housing device to the bottom hole assembly. in standard drilling practice, the drillstring is rotated from the surface to apply torque to the drill bit below. With a mud motor attached to the bottom hole assembly, torque can be applied to the drill bit therefrom, thereby eliminating the need to rotate the drillstring from the surface. Particularly, a positive displacement mud motor is an apparatus to convert the energy of high-pressure drilling fluid into rotational mechanical energy at the drill bit. Alternatively, a turbine-type mud motor may be used to convert energy of the high-pressure drilling fluid into rotational mechanical energy. In most drilling operations, fluids known as “drilling muds” or “drilling fluids” are pumped down to the drill bit through a bore of the drillstring where the fluids are used to clean, lubricate, and cool the cutting surfaces of the drill bit. After exiting the drill bit, the used drilling fluids return to the surface (carrying suspended formation cuttings) along the annulus formed between the cut borehole and the outer profile of the drillstring. A positive displacement mud motor typically uses a helical stator attached to a distal end of the drillstring with a corresponding helical rotor engaged therein and connected through the mud motor driveshaft to the remainder of the BHA therebelow. As such, pressurized drilling fluids flowing through the bore of the drillstring engage the stator and rotor, thus creating a resultant torque on the rotor which is, in turn, transmitted to the drill bit below.
Therefore, when a mud motor is used, it is not necessary to rotate the drillstring to drill the borehole. Instead, the drillstring slides deeper into the wellbore as the bit penetrates the formation. To enable directional drilling with a mud motor, a bent housing is added to the BHA. A bent housing appears to be an ordinary section of the BHA, with the exception that a low angle bend is incorporated therein. As such, the bent housing may be a separate component attached above the mud motor (i.e. a bent sub), or may be a portion of the motor housing itself. Using various measurement devices in the BHA, a drilling operator at the surface is able to determine which direction the bend in the bent housing is oriented. The drilling operator then rotates the drillstring until the bend is in the direction of a desired deviated trajectory and the drillstring rotation is stopped. The drilling operator then activates the mud motor and the deviated borehole is drilled, with the drillstring advancing without rotation into the borehole (i.e. sliding) behind the BHA, using only the mud motor to drive the drill bit. When the desired direction change is complete, the drilling operator rotates the entire drillstring continuously so that the directional tendencies of the bent housing are eliminated so that the drill bit may drill a substantially straight trajectory. When a change of trajectory is again desired, the continuous drillstring rotation is stopped, the BHA is again oriented in the desired direction, and drilling is resumed by sliding the BHA.
One drawback of directional drilling with a mud motor and a bent housing is that the bend may create high lateral loads on the bit, particularly when the system is either kicking off (that is, initiating a directional change) from straight hole, or when it is being rotated in straight hole. The high lateral loads can cause excessive bit wear and a rough wellbore wall surface.
Another drawback of directional drilling with a mud motor and a bent housing arises when the drillstring rotation is stopped and forward progress of the BHA continues with the positive displacement mud motor. During these periods, the drillstring slides further into the borehole as it is drilled and does not enjoy the benefit of rotation to prevent it from sticking in the formation. Particularly, such operations carry an increased risk that the drillstring will become stuck in the borehole and will require a costly fishing operation to retrieve the drillstring and BHA. Once the drillstring and BHA is fished out, the apparatus is again run into the borehole where sticking may again become a problem if the borehole is to be deviated again and the drillstring rotation stopped. Furthermore, another drawback to drilling without rotation is that the effective coefficient of friction is higher, making it more difficult to advance the drillstring into the wellbore. This results in a lower rate of penetration than when rotating, and can reduce the overall “reach”, or extent to which the wellbore can be drilled horizontally from the drill rig.
In recent years, in an effort to combat issues associated with drilling without rotation, rotary steerable systems (“RSS”) have been developed. in a rotary steerable system, the BHA trajectory is deflected while the drillstring continues to rotate. As such, rotary steerable systems are generally divided into two types, push-the-bit systems and point-the-bit systems. in a push-the-bit RSS, a group of expandable thrust pads extend laterally from the BHA to thrust and bias the drillstring into a desired trajectory. An example of one such system is described in U.S. Pat. No. 5,168,941. In order for this to occur while the drillstring is rotated, the expandable thrusters extend from what is known as a geostationary portion of the drilling assembly. Geostationary components do not rotate relative to the formation while the remainder of the drillstring is rotated. While the geostationary portion remains in a substantially consistent orientation, the operator at the surface may direct the remainder of the BHA into a desired trajectory relative to the position of the geostationary portion with the expandable thrusters. An alternative push-the-bit rotary steering system is described in U.S. Pat. No. 5,520,255, in which lateral thrust pads are mounted on a body which is connected to and rotates at the same speed as that of the rest of the BHA and drill string. The pads are cyclically driven, controlled by a control module with a geostationary reference, to produce a net lateral thrust which is substantially in the desired direction.
In contrast, a point-the-bit RSS includes an articulated orientation unit within the assembly to “point” the remainder of the BHA into a desired trajectory. Examples of such a system are described in U.S. Pat. Nos. 6,092,610 and 5,875,859. As with a push-the-bit RSS, the orientation unit of the point-the-bit system is either located on a geostationary collar or has either a mechanical or electronic geostationary reference plane, so that the drilling operator knows which direction the BHA trajectory will follow. Instead of a group of laterally extendable thrusters, a point-the-bit RSS typically includes hydraulic or mechanical actuators to direct the articulated orientation unit into the desired trajectory. While a variety of deflection mechanisms exist, what is common to all point-the-bit systems is that they create a deflection angle between the lower, or output, end of the system with respect to the axis of the rest of the BHA. While point-the-bit and push-the-bit systems are described in reference to their ability to deflect the BHA without stopping the rotation of the drillstring, it should be understood that they may nonetheless include positive displacement mud motors to enhance the rotational speed applied to the drill bit.
Furthermore, in various formations, it is beneficial for the BHA to include a pilot bit and an underreamer to drill a full-gauge bore rather than a lone, single drill bit. In such an assembly, the smaller gauge pilot bit is located at the end of the BHA and is used to drill a pilot bore that is smaller than the final diameter of the borehole. An underreamer, or hole opener, is then located behind the pilot bit, where it is used to enlarge the pilot bore to a desired diameter. Typically, the underreamer must pass through casing that has been set in the previous section of wellbore. After exiting the casing, the underreamer is expanded below the casing to underream the wellbore.
As such, various systems have been proposed in the prior art to directionally drill subterranean boreholes using a BHA that comprises both a drill bit and an underreamer assembly. Particularly, U.S. Pat. No. 5,060,736 (“the '736 patent”) discloses one such BHA. Referring initially to FIG. 1, a bottom hole assembly 100 in accordance with the '736 patent is depicted. Particularly, BHA 100 is shown creating a borehole 102 in a subterranean formation 104. Bottom hole assembly 100 of the '736 patent includes a pilot bit 106, a roller cone-type underreamer 108, and a drilling assembly 110. As depicted in FIG. 1, drilling assembly 110 directionally drills formation 104 through the use of a positive displacement mud motor for a drive mechanism 112 and a bent housing for a directional mechanism 114.
Furthermore, U.S. Pat. No. 6,059,051 (“the '051 patent”) discloses alternative BHA assemblies. Referring now to FIG. 2, a BHA 150 is shown drilling a borehole 152 in a subterranean formation 154. Bottom hole assembly 150 of FIG. 2 includes a pilot bit 156, a first stabilizer 158, a roller cone-type underreamer 160 and a drilling assembly 162 in the order shown. As with FIG. 1, drilling assembly 162 of FIG. 2 includes a bent housing directional mechanism 164 and a mud motor 166 to directionally drill borehole 102 with pilot bit 156 and underreamer 160. Optionally, a second stabilizer 168 may be added to BHA 150 which may be located above (shown) or below drilling assembly 162. Furthermore, if present, second stabilizer 168 may be either a fixed or expandable gauge stabilizer. Finally, first stabilizer 158 may be fixed or rotatable with respect to formation 154.
Referring now to FIG. 3, an alternative BHA 200 in accordance with the '051 patent is shown drilling a borehole 202 in a subterranean formation 204. Bottom hole assembly 200 includes a pilot bit 206, a roller cone-type underreamer 208, an expandable stabilizer 210, a drilling assembly 212, and a second stabilizer 214. As before, drilling assembly 212 is depicted as including a bent housing directional mechanism 216 and a positive displacement mud motor 218. Furthermore, the '051 patent discloses that second stabilizer 214 may be located above (shown) or below drilling assembly 212.
Next, U.S. Pat. Nos. 6,470,977 and 6,848,518 (“the Chen patents”) disclose another alternative BHA assembly. Referring now to FIG. 4, a BHA 250 in accordance with the Chen patents is shown drilling a borehole 252 in a subterranean formation 254. Bottom hole assembly 250 of FIG. 4 includes pilot bit 256 having a gauge section 258, a radial piston-type underreamer 260, and a drilling assembly 262 including a positive displacement mud motor 264 and a bent housing directional mechanism 266. Furthermore, gauge section 258 is described in the Chen patents as having the same diameter of pilot bit 264 and having an axial length of at least 75% of that diameter.
Embodiments of the present invention offer improvements over the known prior art in the field of directional drilling.